Modern petroleum drilling and production operations demand a great quantity of information relating to parameters and conditions downhole. Such information typically includes characteristics of the earth formations traversed by the borehole, along with data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole, which commonly is referred to as “logging”, can be performed by several methods.
As drilling technology improves, there has been an evolution in downhole tools and downhole measurement techniques. A variety of formation sensors or measurement devices are known, including resistivity tools. One conventional technique was referred to as “wireline” and is still employed. Formation sensors were suspended from a probe (or “sonde”), and the sonde is lowered into the borehole after some or all of the well has been drilled. The formation sensors are used to determine certain characteristics of the formations traversed by the borehole. The upper end of the sonde is attached to a conductive wireline that suspends the sonde in the borehole. Power is transmitted to the instruments in the sonde through the conductive wireline. Conversely, the instruments in the sonde communicate information to the surface using electrical signals transmitted through the wireline.
An alternative method of logging is the collection of data during the drilling process. Collecting and processing data during the drilling process eliminates the necessity of removing the drilling assembly to insert a wireline logging tool. It consequently allows the driller to make accurate modifications or corrections as needed to optimize performance while minimizing down time. “Measurement-while-drilling” (MWD) is the term for measuring conditions downhole concerning the movement and location of the drilling assembly while the drilling continues. “Logging-while-drilling” (LWD) is the term for similar techniques, which concentrate more on the measurement of formation parameters. While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For the purposes of this disclosure, the term LWD will be used with the understanding that this term encompasses both the collection of formation parameters and the collection of information relating to the movement and position of the drilling assembly.
In LWD systems, sensors typically are located at the lower end of the drill string. More specifically, the downhole sensors are typically positioned in a cylindrical drill collar positioned near the drill bit. While drilling is in progress these sensors continuously or intermittently monitor predetermined drilling parameters and formation data and transmit the information to a surface detector by some form of telemetry.
Referring now to FIG. 1, a drilling installation is shown. A drilling rig 10 at the surface 12 of the well supports a drill string 14. The drill string 14 penetrates through a work platform 16 and into a borehole 18 that is drilled through earth formations 20 and 21. The drill string 14 may comprise coil tubing 24 from a spool 22 at its upper end, and a bottom hole assembly 26 (commonly referred to as a “BHA”) coupled to the lower end of the coil tubing 24. The BHA 26 may include a drill bit 32, a downhole motor 40, one or more drill collars 28, resistivity tool 50 mounted on collar section 55, LWD sensors positioned in a collar section 55, directional MWD sensors located in a non-magnetic section 60, and one or more stabilizer(s) (not shown) for penetrating through earth formations to create the borehole 18. As shown in FIG. 1, BHA 26 is defined as all of the downhole components from the top of the drill collars 28, down to the drill bit 32, including downhole motor 40. The drill collars 28, which also may be non-magnetic so as not to interfere with the MWD measurements, are used in accordance with conventional techniques to add weight to the drill bit 32 and to stiffen the BHA 26, thereby enabling the BHA 26 to transmit weight to the drill bit 32 without buckling. The weight applied through the drill collars 28 to the bit 32 permits the drill bit to penetrate underground formations.
As the drill bit 32 operates, drilling fluid or mud is pumped from a mud pit 34 at the surface through the hose 37, into the tubing 24, and to the drill bit 32. After flowing through the drill bit 32, the drilling mud rises back to the surface through the annular area between the tubing 24 and the borehole 18, where it is collected and returned to the mud pit 34 for filtering. The drilling mud is used to lubricate and cool the drill bit 32 and to remove cuttings from the borehole 18. The drilling mud may also perform a number of other functions, which could include providing operating power to the downhole motor or other components downhole. The downhole motor or turbine 40 may be used downhole to rotate the drill bit 32.
A downhole controller (not specifically shown in FIG. 1) located in the downhole instrument sub 60 or elsewhere in the BHA controls the operation of the telemetry transmitter 28 and orchestrates the operation of the MWD and LWD sensors and other downhole instrument sub components. The controller may include data encoding circuitry that produces digitally encoded electrical data signals representative of the measurements obtained by the formation sensors and directional sensors. The controller also processes the data received from the sensors and produces encoded signals for transmission to the surface via the telemetry transmitter. The controller may also make decisions based upon the processed data.
Referring now to FIG. 2, a resistivity tool subassembly 102 is shown. The subassembly 102 is provided with one or more regions 106 of reduced diameter. A wire coil 104 is placed in the region 106 and spaced away from the surface of subassembly 102 by a constant distance. Coils 104 and 108 are transmitter coils and coils 110 and 112 are receiving coils. In operation, transmitter coil 104, 108 transmits an interrogating electromagnetic signal which propagates through the wellbore and surrounding formation. Receiver coils 110, 112 detect the interrogating electromagnetic signal and transmits it to the controller, where it is digitized and processed. The controller calculates the electromagnetic signal's amplitude attenuation and phase shift between coils 110 and 112. From the amplitude attenuation and phase shift, the resistivity of the formation can be estimated using conventional techniques.
A problem common to conventional designs is the degrading signal quality of the waveform signal as it is transmitted from the receiver to the controller. As explained with reference to FIG. 2, it is known to use conductive loops of wire as the transmitter(s) and receiver(s), one loop per antenna. Each loop terminates and couples at each end at a circuit card referred to as a “junction box” that is housed in a pressure housing, as shown in FIG. 3. FIG. 3 includes a receiver 301 having two ends that terminate at circuit card 305. Line 320 that supplies power to electronics in circuit card 305 and signal line 325 that carries the analog waveform from circuit card 305 are also shown. The circuit card 305 is generally an industry standard-size circuit board that includes receiver circuitry to detect electrical signals and a transmitter for transmitting the analog waveform to the controller. It can be replaced by any other appropriate circuitry for impedance matching and for transmitting the analog waveform to the controller.
A controller is conventionally located up to several feet from at least one of the receiving antennas. The wiring between the antennas and the controller carries weak (nano-volt level) analog signals, however. This makes these signals susceptible to noise, grounding, pick-up, cross-talk and vibration issues. Each of these issues adversely affects the ability to measure phase shift and signal amplitude accurately, and therefore measurements of formation resistivity.
As shown schematically in FIG. 4, transmitter coil 401, receiver coil 402, and receiver coil 403 each couple to controller 405 through respective circuit cards 411, 412, and 413. The transmitter circuit card has impedance-matching circuitry whereas the receiver circuit card has filtering electronics. Controller 405 includes a microprocessor as well as conditioning and processing components for each receiver channel. For example, each receiver channel may include bandpass filters, a pre-amplifier, gain stabilizer, and an analog-to-digital converter. The processor operates on the waveform data from each receiver coil to establish the phase shift and attenuation between or among the waveforms to generate formation resistivity data.
At the same time, deeper wells are being drilled. Pressures and temperatures become significantly higher at greater well depths. At temperatures approaching 180° Celsius, the performance of existing electronic technologies degrades or fails. This is especially true when these electronics are exposed to these temperatures over the long term. At high temperatures, CMOS electronics tend to be subject to significant leakage. Also, the threshold gate voltages tend to change with temperature, making electronics performance unreliable.
Another environmental effect at elevated temperatures is enhanced electromigration. Electromigration is the movement of metal atoms caused by the flow of electrons. Electromigration can lead to the thinning and separation of interconnections within an integrated circuit. Over time, metal migration tends to degrade performance of the electronics when these electronics are exposed to high temperature.
Efforts have been made to design electronics for use at high temperatures (i.e., above 185° Celsius). However, these efforts have not yielded an ideal, or in many cases even satisfactory, solution. For example, because the electronics are resident in the borehole for only a limited time, the electronics may be shielded from the elevated temperatures by insulation, heat-absorbing materials, and/or active refrigeration. These traditional approaches to configuring electronics for elevated temperature operation have been motivated by the poor performance of many electronics when they are directly exposed to environments with temperatures above 185 Celsius. However, these approaches greatly increase the size of the electronics package, and in the case of active refrigeration, greatly increase the energy consumption by the electronics package. Further, these approaches have not suggested a solution for providing electronics that can remain resident in a well indefinitely.
Another technology that can be used in high temperature applications is known as silicon-on-insulator (SOI). Referring to FIG. 5, this technology generally describes a three-layer construction. Silicon is used as the first, bottom layer. The second, middle layer is made from a type of insulator known to those of ordinary skill. The third top layer is made from silicon. This construction has been satisfactory but is still subject to improvement.
Space limitations downhole can be severe, and part prevent design or installation of a cooling system to cool these electronics even if it were otherwise feasible. A resistivity tool is needed that overcomes these transmission problems. Ideally, it would be desirable to create a resistivity tool that is suitable for use at temperatures well in excess of 200° C. It is desirable for this resistivity tool to stay resident in wells indefinitely at elevated temperatures. Ideally, such data acquisition systems would be compact and able to withstand vibration.